Coiled tubing electronically controlled multilateral access of extended reach wells

ABSTRACT

A bottom hole assembly (BHA) operable to be conveyed within a wellbore extending into a subterranean formation from a wellsite surface via coiled tubing. The BHA may operable to receive a fluid pumped from the wellsite surface via the coiled tubing. The BHA may include a fluid control tool comprising a first fluid passage extending longitudinally through the fluid control tool and a plurality of first fluid outlets extending radially between the first fluid passage and the wellbore. The fluid control tool may be selectively operable to close the first fluid passage and open the plurality of first fluid outlets to pass the fluid into the wellbore via the plurality of first fluid outlets, and close the plurality of first fluid outlets and open the first fluid passage to pass the fluid through first fluid passage. The BHA may further include a tractor operable to move the BHA along the wellbore coupled downhole from the fluid control tool. The tractor may have a second fluid passage fluidly connected with the first fluid passage. The BHA may also include a fluid outlet sub coupled downhole from the tractor having a plurality of second fluid outlets fluidly connected with the first fluid passage and extending radially outward to fluidly connect the second fluid passage and the wellbore, and a bent sub coupled downhole from the fluid outlet sub and operable for steering the BHA.

CROSS-REFERENCE TO RELATED APPLICATION(S)

This application claims the benefit of U.S. Provisional Application Ser.No. 62/571,415, filed Oct. 12, 2017 which is incorporated by referenceherein.

BACKGROUND

To improve efficiency of reservoir-contact and overall well constructioncost reduction, contemporary wellbore completions often have secondarywellbores (i.e., laterals or sidetracks) drilled off of the mainwellbore. Oftentimes, two or more laterals can be drilled at variousdepths and departure angles. However, accessing the laterals duringlater phase (e.g., well completion) can be challenging.

Coiled tubing is a technology that has been expanding its range ofapplication since its introduction to the oil industry in the 1960's.Its ability to pass through completion tubulars and the wide array oftools and technologies that may be used in conjunction with it makecoiled tubing a versatile technology. Typical coiled tubing apparatusinclude surface pumping facilities, a coiled tubing string mounted on areel, a method to convey the coiled tubing into and out of the wellbore(such as an injector head or the like), and surface control apparatus atthe wellhead. Coiled tubing has been utilized for performing welltreatment and/or well intervention operations in existing wellbores,such as, but not limited to, hydraulic fracturing, matrix acidizing,milling, perforating, coiled tubing drilling, and the like.

A coiled tubing intervention operation may utilize an angled arm, whichis placed at a bottom of the coiled tubing string and manipulated in anattempt to steer the coiled tubing string into an intended lateral.Coiled tubing intervention access into the laterals can be accomplishedby deploying a bent-sub at an end of a coiled tubing bottom holeassembly (BHA) and using hydraulic control to manipulate the bent-sub inan attempt to access a lateral junction. The bend-sub is then rotated atvarious angles while passing the BHA over the lateral junction, and apressure signature may confirm lateral contact. While such profilingoperation is a proven operation, profiling introduces a fluid to theformation, does not provide a clear confirmation that a lateral has beenaccessed, is incompatible with hydraulic tractor technologies utilizedfor extended reach wells, and permits only one lateral to be accessedper run in hole.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 2 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 3 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 4 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 5 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 6 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for simplicity andclarity, and does not in itself dictate a relationship between thevarious embodiments and/or configurations discussed. Moreover, theformation of a first feature over or on a second feature in thedescription that follows may include embodiments in which the first andsecond features are formed in direct contact, and may also includeembodiments in which additional features may be formed interposing thefirst and second features, such that the first and second features maynot be in direct contact.

FIG. 1 is a schematic view of at least a portion of an example wellsitesystem 100 according to one or more aspects of the present disclosure,representing an example coiled tubing environment in which one or moreapparatus described herein may be implemented, including to perform oneor more methods and/or processes also described herein. However, it isto be understood that aspects of the present disclosure are alsoapplicable to implementations in which wireline, slickline, and/or otherconveyance means are utilized instead of or in addition to coiledtubing.

FIG. 1 depicts a wellsite surface 125 upon which various wellsiteequipment is disposed proximate a wellbore 120. FIG. 1 also depicts asectional view of the Earth below the wellsite surface 125 containingthe wellbore 120, as well as a bottom hole assembly (BHA) 110 (i.e., atool string) conveyed within the wellbore 120. The wellbore 120 extendsfrom the wellsite surface 125 into one or more subterranean formations130. When utilized in cased-hole implementations, a cement sheath 124may secure a casing 122 within the wellbore 120. However, one or moreaspects of the present disclosure are also applicable to open-holeimplementations, in which the cement sheath 124 and the casing 122 havenot yet been installed in the wellbore 120.

At the wellsite surface 125, the wellsite system 100 may comprise acontrol center 180 comprising processing and communication equipmentoperable to send, receive, and process electrical and/or opticalsignals. The control center 180 is operable to control at least someaspects of operations of the wellsite system 100.

The control center 180 may further comprise an electrical power sourceoperable to supply electrical power to components of the wellsite system100, including the BHA 110. The electrical signals, the optical signals,and the electrical power may be transmitted between the control center180 and the BHA 110 via conduits 184, 186 extending between the controlcenter 180 and the BHA 110. The conduits 184, 186 may each comprise oneor more electrical conductors, such as electrical wires, lines, orcables, which may transmit electrical power and/or electrical controlsignals from the control center 180 to the BHA 110, as well aselectrical sensor, feedback, and/or other data signals from the BHA 110to the control center 180. The conduits 184, 186 may each furthercomprise, or comprise only one or more optical conductors, such as fiberoptic cables, which may transmit light pulses and/or other opticalsignals (hereafter collectively referred to as optical signals) betweenthe control center 180 and the BHA 110.

The conduits 184, 186 may collectively comprise a plurality of conduitsor conduit portions interconnected in series and/or in parallel andextending between the control center 180 and the BHA 110. For example,as depicted in the example implementation of FIG. 1, the conduit 184extends between the control center 180 and a reel 160 of coiled tubing162, such that the conduit 184 may remain substantially stationary withrespect to the wellsite surface 125. The conduit 186 extends between thereel 160 and the BHA 110 via the coiled tubing 162, including the coiledtubing 162 spooled on the reel 160. Thus, the conduit 186 may rotate andotherwise move with respect to the wellsite surface 125. The reel 160may be rotatably supported on the wellsite surface 125 by a stationarybase 164, such that the reel 160 may be rotated to advance and retractthe coiled tubing 162 within the wellbore 120. The conduit 186 may becontained within an internal passage of the coiled tubing 162, securedexternally to the coiled tubing 162, or embedded within the structure ofthe coiled tubing 162. A rotary joint 150, such as may be known in theart as a collector, provides an interface between the stationary conduit184 and the moving conduit 186. In embodiments, the collector or therotary joint 150 may be configured and/or utilized to transmit datawirelessly between the control center 180 and the BHA 110, among othercomponents.

The wellsite system 100 may further comprise a fluid source 140 fromwhich a fluid may be conveyed by a fluid conduit 142 to the reel 160 ofcoiled tubing 162. The fluid conduit 142 may be fluidly connected to thecoiled tubing 162 by a swivel or other rotating coupling (obstructedfrom view in FIG. 1). The coiled tubing 162 may be utilized to conveythe fluid received from the fluid source 140 to the BHA 110 coupled atthe downhole end of the coiled tubing 162 within the wellbore 120.

The wellsite system 100 may further comprise a support structure 170,such as may include or otherwise support a coiled tubing injector 171and/or other apparatus operable to facilitate movement of the coiledtubing 162 in the wellbore 120. Other support structures may be alsoincluded, such as a derrick, a crane, a mast, a tripod, and/or otherstructures. A diverter 172, a blow-out preventer (BOP) 173, and/or afluid handling system 174 may also be included as part of the wellsitesystem 100. For example, during deployment, the coiled tubing 162 may bepassed from the injector 171, through the diverter 172 and the BOP 173,and into the wellbore 120. The BHA 110 may be conveyed along thewellbore 120 via the coiled tubing 162 in conjunction with the coiledtubing injector 171, such as may be operable to apply an adjustableuphole and downhole force to the coiled tubing 162 to advance andretract the BHA 110 within the wellbore 120.

During some downhole operations, fluid may be conveyed through thecoiled tubing 162 and may exit into the wellbore 120 adjacent to the BHA110. For example, the fluid may be directed into an annular area (i.e.,annulus) between the sidewall of the wellbore 120 and the BHA 110through one or more ports (not shown) in the coiled tubing 162 and/orthe BHA 110 to perform an intended well treatment or other downholeoperation. If some or all of the fluid flows in the uphole direction,the diverter 172 may direct the returning fluid out of the wellbore 120to the fluid handling system 174 through one or more conduits 176. Thefluid handling system 174 may be operable to clean the fluid and/orprevent the fluid from escaping into the environment. The fluid may thenbe returned to the fluid source 140 or otherwise contained for lateruse, treatment, and/or disposal.

The BHA 110 may be a single or multiple modules, sensors, and/or tools112, hereafter collectively referred to as the tools 112. For example,the BHA 110 and/or one or more of the tools 112 may be or comprise atleast a portion of a monitoring tool, an acoustic tool, a density tool,a drilling tool, an electromagnetic (EM) tool, a formation testing tool,a fluid sampling tool, a formation logging tool, a formation measurementtool, a gravity tool, a magnetic resonance tool, a neutron tool, anuclear tool, a photoelectric factor tool, a porosity tool, a reservoircharacterization tool, a resistivity tool, a seismic tool, a surveyingtool, a tough logging condition (TLC) tool, a perforating guns or otherperforating tool, a plug setting tool, a plug, a tractor, a fluidcontrol tool, and/or a bent sub among other examples within the scope ofthe present disclosure. The conduit 186 may extend through one or moreof the downhole tools 112, such as may facilitate communication betweenthe control center 180 and the downhole tools 112 and transmission ofelectrical power from the wellsite surface 125 to the downhole tools112.

One or more of the tools 112 may be or comprise a casing collar locator(CCL) operable to detect ends of casing collars by sensing a magneticirregularity caused by the relatively high mass of an end of a collar ofthe casing 122. One or more of the tools 112 may also or instead be orcomprise a gamma ray (GR) tool that may be utilized for depthcorrelation. The CCL and/or GR tools may transmit signals in real-timeto wellsite surface equipment, such as the control center 180, via theconduits 184, 186. The CCL and/or GR tool signals may be utilized todetermine the position of the BHA 110, such as with respect to knowncasing collar numbers and/or positions within the wellbore 120.Therefore, the CCL and/or GR tools may be utilized to detect and/or logthe location of the BHA 110 within the wellbore 120, such as duringintervention operations as described below.

One or more of the tools 112 may also comprise one or more sensors 113.The sensors 113 may include inclination and/or other orientationsensors, such as accelerometers, magnetometers, gyroscopic sensors,and/or other sensors for utilization in determining the orientation ofthe BHA 110 relative to the wellbore 120. The sensors 113 may also orinstead include sensors for utilization in determining petrophysicaland/or geophysical parameters of a portion of the formation 130 alongthe wellbore 120, such as for measuring and/or detecting one or more ofpressure, temperature, strain, composition, and/or electricalresistivity, among other examples within the scope of the presentdisclosure. The sensors 113 may also or instead include fluid sensorsfor utilization in detecting the presence of fluid, a certain fluid, ora type of fluid within the BHA 110 or the wellbore 120. The sensors 113may also or instead include fluid sensors for utilization in measuringproperties and/or determining composition of fluid sampled from thewellbore 120 and/or the formation 130, such as spectrometers,fluorescence sensors, optical fluid analyzers, density sensors,viscosity sensors, pressure sensors, and/or temperature sensors, amongother examples within the scope of the present disclosure. Although thetools 112 are shown and described as comprising one or more sensors 113,it is to be understood that one or more of the tools 112 may notcomprise sensors 113.

The wellsite system 100 may also include a telemetry system comprisingone or more downhole telemetry tools 115 (such as may be implemented asone or more of the tools 112) and/or a portion of the control center 180to facilitate communication between the BHA 110 and the control center180. The telemetry system may be a wired electrical telemetry systemand/or an optical telemetry system, among other examples.

FIGS. 2 and 3 are schematic views of a portion of example wellboresystems 101, 102, each comprising a main substantially vertical wellbore103, 104 and a plurality of corresponding lateral wellbores 105, 106extending from each wellbore 103, 104 at corresponding lateral junctions107, 108. The wellbore systems 101, 102 represent example wellboresystems in which a downhole tool system within the scope of the presentdisclosure, such as the BHA 110 described above, may be utilized,including to perform one or more methods and/or processes according toone or more aspects of the present disclosure. For example, the BHA 110may be steered and conveyed into one or more of the lateral wellbores105, 106 to perform coiled tubing intervention operations according toone or more aspects of the present disclosure.

FIG. 4 is a schematic view of at least a portion of an exampleimplementation of the BHA 110 shown in FIGS. 1-3 and designated in FIG.4 by numeral 200. The following description refers to FIGS. 1-4,collectively.

The BHA 200 is coupled with a coiled tubing string 202 on one end andcomprises a plurality of downhole subs, tools, and/or segments(hereinafter collectively referred to as “tools”) coupled together toform the BHA 200. A power and/or communication conduit 204 extendsthrough at least a portion of the BHA 200, such as may facilitatecommunication between two or more of the downhole tools of the BHA 200.The conduit 204 may extend from the BHA 200 to the control center 180 orother surface equipment located at the wellsite surface 125 through oralong the coiled tubing 162, 202 such as may facilitate communicationand transmission of electrical power between the control center 180 andone or more tools of the BHA 200. The conduit 204 extending through theBHA 200 may comprise a plurality of conduits or conduit segmentsinterconnected in series and/or in parallel, each associated with acorresponding downhole tool of the BHA 200. The conduit 204 may compriseone or more electrical conductors, such as electrical wires, lines, orcables, which may transmit electrical power and/or electrical controlsignals. The conduit 204 may further comprise, or comprise only one ormore optical conductors, such as fiber optic cables, which may transmitlight pulses and/or other optical signals. The optical conductors of theconduit 204 may provide surface to tool telemetry and/or fiber-opticdistributed measurements (e.g., temperature and pressure measurements).In addition to, or in lieu of, electrical power being supplied to theBHA 200 from the conduit 204, the BHA 200 may comprises a battery orbatteries as a part of the BHA for supplying electrical power to the BHA200. In an embodiment, the components or tools of the BHA 200 maycommunicate wirelessly with other components or tools of the BHA 200.

An axial or otherwise longitudinal oriented fluid passage 205 (e.g., abore) extends through at least a portion of the BHA 200, such as maypermit a working fluid (e.g., a treatment fluid, a stimulation fluid,water, or water-based fluid, or a gaseous fluid such as gaseousnitrogen) to pass from the coiled tubing 202 into and through at least aportion of the BHA 200. The fluid passage 205 extending through the BHA200 may comprise a plurality of interconnected individual fluid passagesor passage segments, each provided by a corresponding downhole tool ofthe BHA 200. One or more portions of the conduit 204 may extend throughthe passage 205 and/or through walls of the tools forming the BHA 200and defining the passage 205.

The BHA 200 comprises a multi-lateral tool, such as a bent sub 206, at adownhole end of the BHA 200 to steer the BHA 200 into an intendedlateral wellbore 105, 106. The bent sub 206 may be electricallycontrolled (i.e., steered). The bent sub 206 may be a no flow downholetool, such as may not include an internal flow pathway (e.g., a portionof the passage 205) for passing the working fluid through the bent sub206. The bent sub 206 may also not include fluid outlets for directingthe working fluid out of the bent sub 206. Thus, the BHA 200 facilitateselectronic control of the bent sub 206 to facilitate lateral junctionprofiling, without having to pump the working fluid from the wellsitesurface 125 to manipulate the bent-sub 206. The bent sub 206 may beoperated based on control signals received from the wellsite surface 125via the conduit 186 and/or based on one or more downhole propertiesdetected by one or more of the downhole tools described herein.

The BHA 200 may also include a hydraulic tractor 208 coupled uphole fromthe bent sub 206 and comprising a portion of the fluid passage 205configured to pass the working fluid through the tractor 208. Thetractor 208 may be operated based on control signals received from thewellsite surface 125 along the conduit 204 and/or based on one or moredownhole properties detected by one or more of the downhole toolsdescribed herein.

The BHA 200 permits electrical control of fluid flow paths extendingthrough and out of the BHA 200, such as to direct the working fluidthrough the BHA 200 or divert the working fluid out of the BHA 200 intoan annulus of the wellbore containing the BHA 200. Such fluid flowcontrol permits sensitive tools (e.g., the bent sub 206, the tractor208) of the BHA 200 to be isolated and/or protected from large volumesof working fluid (e.g., acid) and facilitates means for high-rate fluidpumping into the annulus uphole from the sensitive tools without passingthe fluid through the entire BHA 200.

Accordingly, the BHA 200 comprises an electrical circulation sub (ECS)210 operable to control fluid flow direction, such as to selectivelydivert the working fluid flowing through the passage 205 into theannulus (jetting operation) to perform well stimulation or othertreatment. The ECS 210 may also permit the working fluid to pass throughthe ECS 210 and into a portion of the BHA 200 located downhole from theECS 210, such as to facilitate other downhole operations (e.g., tocontrol tractor operation).

The ECS 210 may comprise one or more fluid control valves 209 or otherfluid control members (e.g., balls, flappers, etc.) selectively operableto block fluid flow through the passage 205 and to divert the fluid outof the ECS 210 into the annulus of the wellbore via one or more radiallyoriented fluid outlets 211 (e.g., ports). The fluid control valve 209may be operable to permit fluid flow through the passage 205 and toprevent fluid flow out of the ECS 210 via the fluid outlets 211. Thefluid control valve 209 may be progressively operable, permitting thepassage 205 and/or the outlets 211 to be progressively (i.e., partially)opened and, thus, facilitating adjustable fluid flow control via thepassage 205 and/or the outlets 211. The fluid control valve 209 may beselectively operated by an actuator (not shown) mechanically orotherwise operatively connected with the fluid control valve 209. Thevalve actuator may be, for example, an electrical actuator, such as asolenoid, an electrical motor, or an electrical linear actuator, or theactuator may be a hydraulic actuator, such as a hydraulic cylinder ormotor. The valve actuator may be electrically connected with the conduit204, such as may permit the fluid control valve 209 to be actuated fromthe wellsite surface 125 and/or via a control signal generated by one ormore of the downhole tools. Position of the fluid control valve 209and/or the valve actuator may be monitored via one or more sensors (notshown) operable to monitor position of the fluid control valve 209.

The ECS 210 may be operable to protect one or more of the tools of theBHA 200 from thousands (e.g., 5,000-15,000) of barrels (bbl) of workingfluid (e.g., acid) conveyed per run by diverting the working fluid intothe annulus via the fluid outlets 211. The fluid outlets 211 maycomprise a predetermined size (e.g., inside diameter) or comprisetherein predetermined fluid nozzles sized to optimize acid stimulationor other downhole operations. The fluid outlets 211 of the ECS 210 maybe selectively opened and closed via the fluid control valve 209, suchas to facilitate on-demand fluid flow control operable via electricpower. The ECS 210 may facilitate multiple lateral wellbore access andstimulation without pulling the BHA 200 to the wellsite surface 125 tobe redressed.

The BHA 200 according to one or more aspects of the present disclosuremay further comprise an optical motor head assembly (OMHA) 212, such ashaving a standard downhole contingency functionality and a combinedoptical fiber telemetry line. The BHA 200 may further comprise apressure-temperature-casing (PTC) collar locator module 214, which maybe or operate as the main control center or the “brain” of the downholemeasurement system. The BHA 200 may also comprise a tension andcompression (TC) tool 216 operable to provide downhole weight (i.e.,tension or compression) and/or torque readings for the BHA 200. The TCtool 212 may enhance tractor 208 control operations and provide feedbackto the control center 180 indicative of BHA 200 movement and bent sub206 sensitivity. The BHA 200 may also include a navigation tool 218,which may comprise a direction and inclination sensors and/or a GRmodule. The navigation tool 218 may be a no flow tool, which may notinclude a portion of the fluid passage 205 for passing the working fluiddownhole through the navigation tool 218 or outlet ports for directingthe working fluid out of the navigation tool 218 into the annulus of thewellbore.

The fluid control valve 209 may be operated based on one or moredownhole properties detected by one or more of the downhole tools 214,216, 218 and/or based on control signals received from the wellsitesurface 125 via the conduit 204 and the OMHA 212. For example, the fluidcontrol valve 209 may be operated based on a control signal receivedfrom the wellsite surface 125 via a telemetry portion of the conduit186, 204. The fluid control valve 209 may also be operated based ondistributed temperature measurements generated by the fiber-opticconductor of the conduit 186. Similarly, the tractor 208 may be operatedbased on tension, compression, and/or torque measurements generated bythe TC tool 216.

The BHA 200 may also comprise one or more sondes 220, 222 (i.e.,mechanical modules) operable to provide a portion of the fluid passage205 for passing the working fluid and/or to provide a passage for theconduit 204 (i.e., a control line). For example, the sonde 220 mayprovide a passage for the conduit 204 to be passed through the TC tool216 and the tractor 208 and, thus, provide power and/or telemetry to thetools below the tractor 208. The sonde 222 may be a fluid outlet sub,comprising one or more features of the sonde 220 and also fluid outlets223 (i.e., ports), such as may prevent further flow of the working fluidvia the BHA 200 by directing the working fluid out of the BHA 200 intothe annulus downhole from the tractor 208 and uphole from the navigationtool 218 and the bent sub 206.

Consequently, the BHA 200 according to one or more aspects of thepresent disclosure may facilitate the ability to map and navigate intothe lateral wellbores 105, 106 without having to pump the working fluidthrough the bent sub 206. Because portions of the BHA 200 do not includethe fluid passage 205 extending therethrough (e.g., the navigation tool218, the bent sub 206), the BHA 200 may comprise a slimmerconfiguration, for example, having an outside diameter(s) of about 5.398centimeters (2.125 inches) or smaller. Electrical power and controlfacilitates independent control and/or operation of the tractor 208 andthe bent sub 206. As one or more portions of the BHA 200 may be isolatedfrom the working fluid and/or come into contact with the working fluidat a substantially reduced rate, the BHA 200 may be fully compatiblewith working fluids, such as acids or other stimulation fluids. The BHA200 may be operable to access multiple (e.g., two to five or more)lateral wellbores 105, 106 in a single downhole run. The BHA 200 mayfurther permit lateral wellbore access confirmation, such as byutilizing one or more downhole measurements (e.g., casing collarlocation, gamma, direction, inclination, and/or azimuth). The BHA 200may also facilitate tool power and telemetry combined with fiber-opticsensing in the same stimulation fluid compatible tether (e.g.,cable/control line).

FIG. 5 is a schematic view of another example implementation of the BHA200 shown in FIG. 4 and designated in FIG. 5 by numeral 250. The BHA 250comprises one or more features of the BHA 200, including where indicatedby like reference numbers, except as described below. The followingdescription refers to FIGS. 1-3 and 5, collectively.

Similarly to the BHA 200, the BHA 250 facilitates electronic control offluid flow paths through the BHA 250, such as to selectively direct theworking fluid through the BHA 250 or to divert the working fluid intothe annulus of the wellbore. However, one or more tools or otherportions of the BHA 250 may be larger, comprising an outside diameterthat is substantially larger than the outside diameter of the toolsforming the BHA 200. The larger diameter BHA 250 may permit higherpumping (i.e., flow) rates and/or to support a larger hydraulic tractor.For example, one or more tools or other portions of the BHA 200 may havean outside diameter of about 7.303 centimeters (2.875 inches) or larger.Although one or more tools of the BHA 250 are physically larger than thecorresponding tools of the BHA 200, the same reference numbers are usedto identify the tools of the BHA 250 to indicate these tools otherwisecomprise the same or similar structure and/or mode of operation.

Furthermore, instead of comprising separate navigation tool 218, TC tool216, and PCT locator module 214, the BHA 250 may comprise a singlelarger diameter combination navigation and control tool 252 operable toperform the operations of the navigation tool 218, the TC tool 216, andthe PCT locator module 214.

FIG. 6 is a schematic view of at least a portion of an exampleimplementation of a processing device 300 according to one or moreaspects of the present disclosure. The processing device 300 may executeexample machine-readable instructions to implement at least a portion ofone or more of the methods and/or processes described herein, and/or toimplement a portion of one or more of the example downhole toolsdescribed herein. The processing device 300 may be or comprise, forexample, one or more processors, controllers, special-purpose computingdevices, servers, personal computers, personal digital assistant (PDA)devices, smartphones, internet appliances, and/or other types ofcomputing devices. Moreover, while it is possible that the entirety ofthe processing device 300 shown in FIG. 6 is implemented within one ormore tools of the BHA 110, 200, 250 described above, one or morecomponents or functions of the processing device 300 may also or insteadbe implemented in wellsite surface equipment, perhaps including thecontrol center 180 depicted in FIG. 1.

The processing device 300 may comprise a processor 312, such as ageneral-purpose programmable processor, for example. The processor 312may comprise a local memory 314, and may execute program codeinstructions 332 present in the local memory 314 and/or another memorydevice. The processor 312 may execute, among other things,machine-readable instructions or programs to implement the methodsand/or processes described herein. The programs stored in the localmemory 314 may include program instructions or computer program codethat, when executed by an associated processor, cause a controllerand/or control system implemented in surface equipment and/or a downholetool to perform tasks as described herein. The processor 312 may be,comprise, or be implemented by one or more processors of various typesoperable in the local application environment, and may include one ormore general-purpose processors, special-purpose processors,microprocessors, digital signal processors (DSPs), field-programmablegate arrays (FPGAs), application-specific integrated circuits (ASICs),processors based on a multi-core processor architecture, and/or otherprocessors.

The processor 312 may be in communication with a main memory 317, suchas via a bus 322 and/or other communication means. The main memory 317may comprise a volatile memory 318 and a non-volatile memory 320. Thevolatile memory 318 may be, comprise, or be implemented by random accessmemory (RAM), static random access memory (SRAM), synchronous dynamicrandom access memory (SDRAM), dynamic random access memory (DRAM),RAMBUS dynamic random access memory (RDRAM), and/or other types ofrandom access memory devices. The non-volatile memory 320 may be,comprise, or be implemented by read-only memory, flash memory, and/orother types of memory devices. One or more memory controllers (notshown) may control access to the volatile memory 318 and/or thenon-volatile memory 320.

The processing device 300 may also comprise an interface circuit 324.The interface circuit 324 may be, comprise, or be implemented by varioustypes of standard interfaces, such as an Ethernet interface, a universalserial bus (USB), a third generation input/output (3GIO) interface, awireless interface, and/or a cellular interface, among other examples.The interface circuit 324 may also comprise a graphics driver card. Theinterface circuit 324 may also comprise a communication device, such asa modem or network interface card, to facilitate exchange of data withexternal computing devices via a network, such as via Ethernetconnection, digital subscriber line (DSL), telephone line, coaxialcable, cellular telephone system, and/or satellite, among otherexamples.

One or more input devices 326 may be connected to the interface circuit324. One or more of the input devices 326 may permit a user to enterdata and/or commands for utilization by the processor 312. Each inputdevice 326 may be, comprise, or be implemented by a keyboard, a mouse, atouchscreen, a track-pad, a trackball, an image/code scanner, and/or avoice recognition system, among other examples.

One or more output devices 328 may also be connected to the interfacecircuit 324. One or more of the output devices 328 may be, comprise, orbe implemented by a display device, such as a liquid crystal display(LCD), a light-emitting diode (LED) display, and/or a cathode ray tube(CRT) display, among other examples. One or more of the output devices328 may also or instead be, comprise, or be implemented by a printer,speaker, and/or other examples.

The processing device 300 may also comprise a mass storage device 330for storing machine-readable instructions and data. The mass storagedevice 330 may be connected to the interface circuit 324, such as viathe bus 322. The mass storage device 330 may be or comprise a floppydisk drive, a hard disk drive, a compact disk (CD) drive, and/or digitalversatile disk (DVD) drive, among other examples. The program codeinstructions 332 may be stored in the mass storage device 330, thevolatile memory 318, the non-volatile memory 320, the local memory 314,and/or on a removable storage medium 334, such as a CD or DVD.

The mass storage device 330, the volatile memory 318, the non-volatilememory 320, the local memory 314, and/or the removable storage medium334 may each be a tangible, non-transitory storage medium. The modulesand/or other components of the processing device 300 may be implementedin accordance with hardware (such as in one or more integrated circuitchips, such as an ASIC), or may be implemented as software or firmwarefor execution by a processor. In the case of firmware or software, theimplementation can be provided as a computer program product including acomputer readable medium or storage structure containing computerprogram code (i.e., software or firmware) for execution by theprocessor.

The present disclosure is further directed to one or more methods. Themethods described below and/or other operations described herein may beperformed utilizing or otherwise in conjunction with at least a portionof one or more implementations of one or more instances of the apparatusshown in one or more of FIGS. 1-6 and/or otherwise within the scope ofthe present disclosure. However, the methods and operations describedherein may be performed in conjunction with implementations of apparatusother than those depicted in FIGS. 1-6 that are also within the scope ofthe present disclosure. The methods and operations may be performedmanually by one or more human operators and/or performed or caused, atleast partially, by the processing device 300 executing codedinstructions 332 according to one or more aspects of the presentdisclosure. For example, the processing device 300 may receive inputsignals and automatically generate and transmit output signal to operateor cause a change in an operational parameter of one or more pieces ofthe wellsite equipment described above. However, the human operator mayalso or instead manually operate the one or more pieces of wellsiteequipment via the processing device based on sensor signals displayed.

One of the methods within the scope of the present disclosure may be orcomprise conveying the BHA 200, 250 in hole to a target depth. As theBHA 200, 250 is run in-hole (RIH), the ECS 210 may be operated to permitthe working fluid to pass thru the BHA 200, 250. The working fluid maybe pumped from the wellsite surface 125 via the coiled tubing 162 andthrough the tractor 208 at low rates to aide with the conveyanceprocess, such as for lubrication and/or circulating debris. Once thetractor 208 is intended to be operated (i.e., engaged), the pumping(i.e., flow) rate of the working fluid may be increased to reach apredetermined “tractoring” fluid flow and/or pressure to operate thetractor 208. Thus, the use, the type, and/or the quantity of the workingfluid may be controlled, limited, or reduced to instances when use ofthe tractor 208 is needed to achieve maximum or otherwise intended(i.e., target) well depth. Once at the intended depth is reached, thefluid pumping may be stopped while lateral access operation isinitiated.

Another method within the scope of the present disclosure may be orcomprise performing profiling operations. Such method may compriseutilizing the depth correlation functions of the PTC collar locatormodule 214 and/or the navigation tool 218 to position the BHA 200, 250within a hole (e.g., the wellbore 104, the lateral wellbore 105, 106)just below (i.e., downhole from) the wellbore lateral junction 107, 108.Thereafter, the bent sub 206 may be engaged via an electronic signal,the BHA 200, 250 may be pulled out of the hole past the lateral junction107, 108 while a surface acquisition system of the control center 180 atthe wellsite surface 125 monitors the BHA 200, 250 to validate a changein the position of the bent sub 206 (change in position confirms lateraljunction contact). If the lateral junction 107, 108 is not identified,the BHA 200, 250 may be ran back in hole, the bent-sub 206 may berotated or deflected between about 10 and 20 degrees or another anglewith respect to an axis of the BHA 200, 250, such as that disclosed inU.S. Pat. No. 6,349,768, incorporated by reference herein in itsentirety, and the BHA 200, 250 may be pulled out of the hole past thelateral junction 107, 108 while the surface acquisition system validatesthe change in rotational position of the bent sub 206. Such process maybe repeated until a confirmation that the bent sub 206 is in the lateraljunction is received. The BHA 200, 250 may then be lowered into anintended lateral wellbore 105, 106, which may be confirmed via the gammaand/or direction and inclination measurements of the navigation tool218. The BHA 200, 250 may then be lowered into the intended lateralwellbore 105, 106 with or without utilizing the tractor 208, asdescribed above.

Still another method within the scope of the present disclosure may beor comprise performing stimulation treatment (e.g., acidizing) of thewell. Once the BHA 200, 250 reaches the target depth, the ECS 210 may beoperated to divert the working fluid flowing through the BHA 200, 250into the annulus of the lateral wellbore 105, 106 via the fluid outlets211, ensuring that no volume of acid is pumped through the tractor 208.Once the stimulation treatment is completed, the fluid control valve 209of the ECS 210 may be operated to close the outlets 211 and pass theworking fluid through the BHA 200, 250 downhole from the ECS 210 and thetractor 208. The processes described above may be repeat for a pluralityof lateral wellbores 107, 108 without pulling the BHA 200, 250 to thewellsite surface 125 for redress.

In view of the entirety of the present disclosure, including thefigures, a person having ordinary skill in the art will recognize thatthe present disclosure is directed to an apparatus operable to controlor steer a downhole apparatus into a wellbore lateral junction based onelectrical signals sent from a wellsite surface for well interventiontreatment. For example, the apparatus may be operable to completelyrotate, partially rotate, completely incline, and/or partially incline abottom end of a downhole tool based on a signal/command sent via atelemetry conduit on demand from a wellsite surface.

The present disclosure is further directed to an apparatus operable tomap the wellbore lateral junction dimensions by determining status andposition of the downhole apparatus for well intervention treatment. Forexample, the apparatus may be operable to read an electrical signal todetermine positioning as well as one or more of a rotation status, aninclination status, and an extension status of the bottom end of adownhole apparatus.

The present disclosure is further directed to an apparatus operable tocontrol or direct the path of fluid pumped from a wellsite surfaceconveyed through a wellbore lateral junction based on electrical signalssent from the wellbore surface for well intervention treatment. Forexample, the apparatus may be operable to fully open, fully close,and/or partially open a radially oriented fluid pathway in a downholetool conveyed through a wellbore lateral junction based on asignal/command sent through a telemetry conduit on demand from awellsite surface. The apparatus may be further operable to fully open,fully close, and/or partially open an axial (e.g., longitudinal)oriented fluid pathway through a downhole tool conveyed through awellbore lateral junction based on a signal/command sent through atelemetry conduit on demand from a wellsite surface. The apparatus mayalso be operable to fully open, fully close, and/or partially openanother (i.e., randomly oriented) fluid pathway in a downhole toolconveyed through a wellbore lateral junction based on a signal/commandsent through a telemetry conduit on demand from a wellsite surface.

The present disclosure is also directed to an apparatus operable tocontrol or direct the path of fluid pumped from the wellsite surfacethrough a wellbore lateral junction based on distributed temperaturemeasurements for well intervention treatment. For example, the apparatusmay be operable to fully open fully close, and/or partially open aradially oriented fluid pathway in a downhole tool conveyed through awellbore lateral junction based on distributed temperature measurementson demand from a wellsite surface. The apparatus may be further operableto fully open, fully close, and/or partially open an axial orientedfluid pathway in a downhole tool conveyed through a wellbore lateraljunction based on distributed temperature measurements on demand fromsurface. The apparatus may also be operable to fully open, fully close,and/or partially open another (i.e., randomly oriented) fluid pathway ina downhole tool conveyed through a wellbore lateral junction based ondistributed temperature measurements on demand from surface.

The present disclosure is also directed to an apparatus operable tocontrol or steer a downhole tractor apparatus into a wellbore lateraljunction based on downhole load measurements for well interventiontreatment. For example, the apparatus may be operable to fully activate,partially activate, and/or stop operating (i.e., tracking) the tractorapparatus of a downhole tool based on tension, compression and torquemeasurements on demand from surface.

The present disclosure is also directed to an apparatus operable todetermine status and position of a valve in a downhole apparatusconveyed through a wellbore lateral junction from a wellsite surface.For example, the apparatus may be operable to read an electrical signalto determine the status and positioning of a linear actuator, a radialactuator, or another actuator that controls the downhole valve.

The present disclosure is still further directed to an apparatusoperable to manipulate a valve in a downhole apparatus conveyed througha wellbore junction lateral from the wellsite surface. For example, theapparatus may be operable to send an electrical signal to cause movementof a linear, radial, or another actuator that controls the downholevalve.

The foregoing outlines features of several embodiments so that a personhaving ordinary skill in the art may better understand the aspects ofthe present disclosure. A person having ordinary skill in the art shouldappreciate that they may readily use the present disclosure as a basisfor designing or modifying other processes and structures for carryingout the same functions and/or achieving the same benefits of theembodiments introduced herein. A person having ordinary skill in the artshould also realize that such equivalent constructions do not departfrom the spirit and scope of the present disclosure, and that they maymake various changes, substitutions and alterations herein withoutdeparting from the spirit and scope of the present disclosure.

What is claimed is:
 1. An apparatus comprising: a bottom hole assembly(BHA) operable to be conveyed within a wellbore extending into asubterranean formation from a wellsite surface via coiled tubing,wherein the BHA is operable to receive a fluid pumped from the wellsitesurface via the coiled tubing, and wherein the BHA comprises: a fluidcontrol tool comprising a first fluid passage extending longitudinallythrough the fluid control tool and a plurality of first fluid outletsextending radially between the first fluid passage and the wellbore. 2.The apparatus of claim 1 wherein the fluid control tool is selectivelyoperable to: close the first fluid passage and open the plurality offirst fluid outlets to pass the fluid into the wellbore via theplurality of first fluid outlets; and close the plurality of first fluidoutlets and open the first fluid passage to pass the fluid through firstfluid passage.
 3. The apparatus of claim 2 wherein the BHA furthercomprises a tractor operable to move the BHA along the wellbore coupleddownhole from the fluid control tool, wherein the tractor comprises asecond fluid passage fluidly connected with the first fluid passage. 4.The apparatus of claim 3 wherein the BHA further comprises a fluidoutlet sub coupled downhole from the tractor and comprising a pluralityof second fluid outlets fluidly connected with the first fluid passageand extending radially outward to fluidly connect the second fluidpassage and the wellbore.
 5. The apparatus of claim 4 wherein the BHAfurther comprises a bent sub coupled downhole from the fluid outlet suband operable for steering the BHA.
 6. The apparatus of claim 2 whereinthe fluid control tool is actuated by a valve actuator.
 7. The apparatusof claim 6 wherein the valve actuator is an electric actuator.
 8. Theapparatus of claim 6 wherein the valve actuator is a hydraulic actuator.9. A system for accessing at least one lateral wellbore in amultilateral wellbore, comprising: a coiled tubing extending from awellsite surface into the wellbore; a control center operable to send,receive and process control signals; a bottom hole assembly (BHA)operable to be conveyed within the wellbore via the coiled tubing,wherein the BHA is operable to receive a fluid pumped from the wellsitesurface via the coiled tubing, and wherein the BHA comprises: anelectrical circulation sub comprising a first fluid passage extendinglongitudinally through the electrical circulation sub and a plurality offirst fluid outlets extending radially between the first fluid passageand the wellbore, the electrical circulation sub configured toselectively divert fluid, based on control signals from the controlcenter, from the first fluid passage to the first fluid outlets and thewellbore; and a bent sub configured to be rotated with respect to anaxis of the BHA, the bent sub electronically controlled via controlsignals from the control center without the need to have the fluidpumped therethrough.
 10. The system of claim 9 wherein the electricalcirculation sub diverts fluid to protect at least the bent sub from thefluid when performing a downhole operation with the fluid.
 11. Thesystem of claim 9 wherein the BHA further comprises a tractor andwherein the electrical circulation sub facilitates operation of thetractor via selectively diverting fluid.
 12. The system of claim 9wherein the BHA further comprises a navigation tool.
 13. The system ofclaim 9 wherein the BHA further comprises a tension compression tool.14. The system of claim 9 wherein the BHA further comprises apressure-temperature-casing collar locator module.
 15. A method foraccessing a wellbore in a multilateral system, comprising: providing acoiled tubing and a control center at a wellsite surface; conveying thecoiled tubing and a bottom hole assembly (BHA) from the wellsite surfaceinto the wellbore to a target depth, the BHA comprising an electricalcirculation sub (ECS) operable to allow fluid flow through the coiledtubing and through the BHA, to divert fluid flow from the coiled tubingout the BHA into the wellbore, or both; and a tractor for conveying theBHA and the coiled tubing through the wellbore; sending control signalsfrom the control center to configure the ECS to permit the working fluidto pass through the BHA when conveying; upon reaching a target depth,sending control signals control center to configure the ECS to divertthe working fluid from the ECS and into the wellbore; and performing awellbore operation with the fluid, thereby controlling the flow of theworking fluid through the BHA to instances when use of the tractor isneeded to achieve the target well depth
 16. The method of claim 15,wherein the BHA further comprises a bent sub configured to be rotatedwith respect to an axis of the BHA and further comprising sending asignal from the control center to rotate the bent sub during thewellbore operation.
 17. The method of claim 16 further comprisingdetermining a status and position of the BHA for a well interventiontreatment.
 18. The method of claim 17 wherein performing comprisesperforming a profiling operation.
 19. The method of claim 15, whereinperforming comprises performing a stimulation treatment.
 20. The methodof claim 19, wherein performing comprises performing a acidizingtreatment.